Hydrocarbon Generation Potential Research Articles

The influence of Early Cretaceous paleoclimate warming event on sedimentary environment evolution and organic matter sources in Yin'e Basin: Evidence from petrology and molecular geochemistry

The lacustrine organic-rich fine-grained sedimentary rocks of the Early Cretaceous Bayingebi Formation are widely distributed in the Yin'e Basin and they have become important source rocks for oil and gas exploration. To reveal the influence of paleoclimate warming event on sedimentary environment evolution and organic matter sources, the petrological and molecular geochemical analyses of the upper member of the Bayingebi Formation (K1b2) were carried out using optical microscopy, X-ray diffraction, scanning electron microscopy, Rock-Eval pyrolysis and gas chromatography–mass spectrometry, in order to establish the paleoecological models of the Early Cretaceous freshwater and saline lakes. The oil shale and dark mudstone of K1b2 are both in the immature-early mature stage and have good potential for hydrocarbon generation, with a dominance of type I and type II1 kerogen. Two types of primary dolomite were found in this formation: microcrystalline dolomite with uniform structure, and the microbially originated spherical dolomite aggregates. The K1b2 can be divided into four units based on its lithology and logging curve characteristics. Unit II was deposited in the peak of lake development, under the warm-humid paleoclimate with abundant annual precipitation. There was greater influx of freshwater than other units, which resulted in the unstable stratification of the water column and less reducing condition of the lake bottom water body. Lower aquatic organisms and vascular plants were unprecedentedly prosperous, which were indicated by short-term thriving phenomena of telalginite, and the large input of terrestrial OM and highest abundance of the OM compared to other units. A lake water salinization event occurred during the sedimentation period of Unit III under the cooling climate, causing a transition from a freshwater lake to a high-salinity lake with reducing condition and stable stratification of the water column. Salinity of lake water increased the competitiveness of salt-tolerant algae and bacteria. The salty environment is beneficial for the thriving of single to halophilic genus of microorganism and lead to significantly lower abundance of telalginite. The biological sources of OM were mainly bacteria, algae and emergent plants, with limited contribution of terrestrial higher plants. The anoxic alkaline environment and high salinity condition at the lake bottom were beneficial for the formation of carbonate minerals and the preservation of OM. This were characterised by medium abundance of OM and high hydrocarbon generation potential. The study on the petrological and molecular geochemical characteristics of these organic-rich fine-grained sedimentary rocks is of great significance for investigating the genetic mechanisms and resource potential of oil and gas.

Total organic carbon content logging prediction based on machine learning: A brief review

The total organic carbon content usually determines the hydrocarbon generation potential of a formation. A higher total organic carbon content often corresponds to a greater possibility of generating large amounts of oil or gas. Hence, accurately calculating the total organic carbon content in a formation is very important. Present research is focused on precisely calculating the total organic carbon content based on machine learning. At present, many machine learning methods, including backpropagation neural networks, support vector regression, random forests, extreme learning machines, and deep learning, are employed to evaluate the total organic carbon content. However, the principles and perspectives of various machine learning algorithms are quite different. This paper reviews the application of various machine learning algorithms to deal with total organic carbon content evaluation problems. Of various machine learning algorithms used for TOC content predication, two algorithms, the backpropagation neural network and support vector regression are the most commonly used, and the backpropagation neural network is sometimes combined with many other algorithms to achieve better results. Additionally, combining multiple algorithms or using deep learning to increase the number of network layers can further improve the total organic carbon content prediction. The prediction by backpropagation neural network may be better than that by support vector regression; nevertheless, using any type of machine learning algorithm improves the total organic carbon content prediction in a given research block. According to some published literature, the determination coefficient (R2) can be increased by up to 0.46 after using machine learning. Deep learning algorithms may be the next breakthrough direction that can significantly improve the prediction of the total organic carbon content. Evaluating the total organic carbon content based on machine learning is of great significance.

Source rock properties and kerogen decomposition kinetics of Eocene shales from petroliferous Barmer basin, western Rajasthan, India

Hydrocarbon exploration and production are going on in Barmer basin (Rajasthan, India) for more than a decade. The potential source rocks are of Paleocene – Eocene age, and Mesozoic siltstones form the reservoirs. The western and central portions of the Rajasthan basin are characterised by extensive lignite formations, which can be promising for artificial transformation to oil and gas. We study the source rock properties, depositional environments and hydrocarbon generation potential of the Paleogene lignitic shales of the Giral lignite mine and the Cretaceous Sarnu siltstones for their source and reservoir rock potentiality. The total organic carbon content (TOC) of the Giral samples range between 0.76 and 49.83 wt% and the thermal maturity, as reflected by the pyrolysis Tmax, lies between 412 and 468 °C. Sarnoo siltstones, on the other hand, have a very low TOC ranging from 0.02 to 0.08 wt% and a Tmax of 320–608 °C. The higher TOC and a lower oxygen index (OI) of Giral lignites and shaly lignites indicate the prevalence of a reducing depositional environment. Bulk organic geochemical parameters involving kerogen pyrolysis and thermal degradation kinetics indicate a more promising hydrocarbon generation potential in the lignite than shales, which, however exhibits higher thermal maturity of organic matter. Giral lignites as well as shales show dominantly Type-III heterogeneous kerogen, which is sourced from terrestrial organic matter. This is also corroborated by a broader distribution of activation energy derived from the thermal decomposition of the kerogen. The kerogen transformation ratio (KTR) and the hydrocarbon generation rate (HGR) suggest a considerably earlier and quicker kerogen transformation. Samples from the Sarnoo area offer no significant information on the source rock characteristics, due to their lean organic nature. However, lignites and shaly lignites of the Giral mine are identified as excellent candidates for their suitability towards easy conversion into hydrocarbon products through artificial techniques.

Characteristics and Controlling Factors of the Chang 8 Oil Reservoir in the Yanchi Area of the Ordos Basin: A Case Study of Well G20

In the Ordos Basin, the Chang 8 oil reservoir of the Triassic Yanchang Formation is the main target of oil exploration and development and there are many factors affecting the hydrocarbon accumulation. Well G20 is an important exploration well in the Yanchi area in the northwestern part of the basin, and the core of the Chang 8 reservoir was sampled and tested to determine the source rocks, trace element composition, mineral composition, reservoir physical properties, and oil-bearing properties. The results show that the rock retrieved exhibits delta plain subfacies; the range of the Chang 8 water body was large, with a gentle slope, and the climate was relatively dry. These findings suggest that this reservoir was deposited in an environment in which sedimentary sand body could easily form. The Chang 8 sandstone reservoir pores are dominated by intergranular pores and feldspar intragranular dissolution pores, indicating that the Chang 8 reservoir is a low-porosity and low-permeability reservoir. Chang 7 source rocks from this area have a type I-II1 hydrocarbon-generating potential, with an average total organic carbon (TOC) content of 5.99% and vitrinite reflectance (Ro) value of 0.48%. Combined with the regional sedimentary evolution, tectonic movement, and reservoir distribution, it is considered that due to the lack of lithologic traps or low-amplitude structural traps, G20 produced water in well testing. The Chang 8 oil reservoir in the Yanchi area can be divided into structural reservoirs and structural-lithologic reservoirs. The conventional oil and gas reservoir exploration ideas of “thick sand belt” and “reservoir sweet spot” are not applicable here. The lithology traps or low-amplitude structural traps and areas with good preservation conditions are the main directions for the next phase of exploration in the northwestern part of the Ordos Basin.

Assessment of hydrocarbon generative potential of Late Paleocene coals from East Khasi Hills, Meghalaya, North-East India

The study area is situated in the Meghalaya state (East Khasi Hills), North-East India. The notable petroliferous basins that were formed during the Paleogene time occurred in the state of northeast India. This work focused on characterizing the source rock of Late Paleocene (Shella Formation) of Pynursla-Lynkerdem area, East Khasi Hills, Meghalaya for their hydrocarbon potential based on Rock-Eval pyrolysis and elemental data. The coals of the Pynursla-Lynkerdem area have been characterized by high total organic carbon (TOC) range between 67.2 wt% and 74.5 wt%. The remaining hydrocarbon yield (S 2) ranges from 215.5 to 294.0 mg HC/g rock. S 2 and TOC data plots entail that these coals contain Type II–III kerogen and can act as a good hydrocarbon source rock. The hydrogen index (HI) ranges from 311.1 to 405.7 mg HC/g TOC, which indicates most of the sample can generate gases. T max varies between 405 and 433 °C (less than 435 °C), revealing the immaturity of organic matter. The plot of elemental composition places these samples from sub-bituminous to high volatile bituminous in rank and furnishes these coals’ suitability for gasification.

Characterization of organic matter from the Cretaceous sedimentary and volcano-sedimentary strata from Livingston Island, Antarctic Peninsula: Insights from organic petrology, molecular proxies and carbon and hydrogen isotopes

Rock samples from the Early to Late Cretaceous marine and non-marine strata of Livingston Island, South Shetland Islands, Antarctica, were studied. Organic matter (OM) originates predominantly from terrestrially-derived organic particles. Mostly highly fragmented plant remains, and locally vitrinite/semifusinite as part of plant compressions/imprints or thin vitrain/fusain lenses, are present. Bulk geochemical results indicate Type III kerogen with poor hydrocarbon generation potential. Tmax and molecular proxies (i.e hopane and sterane isomerization ratios, MPI-1, etc.), together with the local presence of oily droplets, argue for an early oil window maturity, probably caused by regional volcanic activity. In contrast to the results of petrography and Rock-Eval pyrolysis, molecular composition of extractable OM is dominated by short-chain n-alkanes, saturated fatty acids (FAs) and n-alkanols implying a major contribution of autochthonous OM. This contradiction is most likely caused by decomposition of OM from plant tissues, the predominance of wood remains (i.e., xylites) and the low input of FAs from cuticular waxes. The presence of terrestrial OM is indicated by plant wax-derived lipids and resinous compounds. Prominent even carbon number predominance in the short-chain n-alkane range argue for deposition/decomposition under reducing environmental settings, most probably caused by high sedimentation rates and quick burial. Terpenoid biomarker compositions indicate contribution from conifers, whereas input from phytoplankton/algal organic matter is evidenced by C27 steroids, the presence of 4-methyl steranes and dinosterol. Low concentrations of hopanoids and C15 and C17 branched n-FAs argue for limited bacterial input. Only in one sample from Hannah Point, a difference between the δ13C values of the short-chain versus long-chain n-alkanes was obtained, arguing for mixed OM sources (i.e., autochthonous input, land plants). The presence of charred organic matter in most of the studied samples, together with the considerable concentrations of combustion-derived PAHs, argue for the common occurrence of wildfires within the terrestrial environments. Despite the active volcanic arc settings, the compound specific carbon and hydrogen isotopes do not record significant changes in climatic/hydrological conditions, although some short-term events cannot be ruled out. Instead, the δ13C and δ2H isotopic fractionation is most likely caused by the specific biosynthetic mechanisms of the plants and the global carbon and hydrogen cycles.

Sedimentary environment and organic matter enrichment of black mudstones from the upper Triassic Chang-7 member in the Ordos Basin, Northern China

The black mudstone of the Chang-7 Member is the most important source rock in the Ordos Basin. In order to understand the paleo-climate, weathering, redox conditions, salinity, water temperature, water depth, and primary productivity under which black mudstone of the Chang-7 Member was deposited, we have analyzed total organic carbon (TOC), rock pyrolysis parameters, major elements, and trace elements of 60 black mudstone samples from the Chang-7 Member of the Yanchang Formation in the Ordos Basin. Geochemical indicators such as TOC, volatile hydrocarbon and residual hydrocarbon (S1 + S2), hydrogen index (HI), chloroform asphalt “A”, maximum pyrolysis peak temperature (Tmax), Vitrinite reflectance (Ro), kerogen macerals, and other organic indicators, show that the kerogen type of the Chang-7 Member was type I–II1, the thermal evolution of organic matter was in the mature stage, and it has good hydrocarbon generation potential. The major and trace element characteristics, such as C-value, Sr/Cu, Rb/Sr and Mg/Ca ratios, chemical alteration index(CIA), Sr/Ba, B, Ga-B-Rb trace element triangle, B/Ga, 1000 × Rb/K2O, V/(V + Ni), pristane/phytane ratio (Pr/Ph), foraminiferal Mg/Ca, and Co values indicate that the sedimentary environment of the Chang-7 Member was semi-arid and semi-humid, with continental freshwater, a reductive sedimentary environment, and an average paleotemperature of 16 °C. Based on the analysis of Baxs and Ba/Al ratio, the Chang-7 Member has medium–high primary productivity, which together with the sedimentary environment, played an important role in the enrichment and preservation of organic matter.

Oil generation model of the liptinite-rich coals: Palaeogene in the Xihu Sag, East China Sea Shelf Basin

Hydrocarbon generation from liptinite-rich coal is an important focus in petroleum geology as well as in coal geology. The confined pyrolysis experiment in gold tubes is an effective approach in assessing the hydrocarbon generation potential of coals. Xihu Sag is one of the most hydrocarbon-rich Cenozoic basins in the East China Sea Shelf Basin, and oil and gas are believed to be generated from Paleogene liptinite-rich coals. Coals from the Pinghu and Huagang formations of the Paleogene have a liptinite content mostly higher than 10%, and contain type II-III organic matter. The HImax values, H/C, and O/C ratios of these coals are in the range of 200–300 mg/g·TOC, 0.97 to 1.42, and 0.08 to 0.20, respectively. All these characteristics demonstrate good potential for these coals to generate oil. Experimental data show that the maximum cumulative yields of oil produced range from 122.74 to 154.09 mg/g·TOC, and the coals in the sag can also generate oil in their immature stage (Ro = 0.36%–0.5%) due to abundant resinite (mostly higher than 5%). To further assess the characteristics and processes of petroleum generation under geological conditions, we reconstructed the liquid hydrocarbon generation history of the coals in three structural units of Xihu Sag, i.e., the West Slope Belt, West Sub-sag, and Central Anticlinal Belt. For the coals in the Pinghu Formation, the West Slope Belt is a favorable oil-forming area, while the West Sub-sag and the Central Anticlinal Belt are less favorable oil-forming areas. For the coals in the Huagang Formation, the West Slope Belt is a favorable asphaltene (ΣC14+)-forming area, while the West Sub-sag and Central Anticlinal Belt are favorable light hydrocarbon (ΣC6-14)-forming areas. Results of this study will contribute to a better understanding of the characteristics and potential of oil generation from the liptinite-rich coals and are of significance for oil exploration in the Xihu Sag.

An evaluation of Maastrichtian-Paleocene source rock interval on the western flank of Niger Delta Basin, Nigeria: Implications for hydrocarbon prospectivity

Maastrichtian and Paleocene shales recovered from a vertical exploratory well on the western flank of Niger Delta Basin, close to the boundary of the Dahomey (Benin) Basin, were studied for their possible contribution to the hydrocarbon potential of the basin. The organic matter richness, kerogen types, and thermal maturity of the studied shale samples and implications of hydrocarbon generation potential were determined based on results of TOC/Rock-Eval analysis. The Maastrichtian and Paleocene shale samples are characterized by total organic carbon (TOC) values of up to 4.70 wt. % and S2 (hydrocarbon-generating potential) values range from 0.68 to 2.69 mgHC/g rock, indicating poor to fair source potential. The presence of type III and type IV kerogen is indicative of poor-quality organic matter that has the potential to generate gaseous hydrocarbon. This study suggests that the Maastrichtian and Paleocene source rocks on the western flank of the Niger Delta Basin are immature to early mature stage, and could not have generated a commercial amount of hydrocarbon.

Controls of marine shale gas accumulation in the eastern periphery of the Sichuan Basin, South China

This study examines the mechanisms that most influenced the accumulation of shale gas deposits of the Lower Cambrian Niutitang, Upper Ordovician Wufeng, and Lower Silurian Longmaxi formations of the eastern periphery of the Sichuan Basin. Abundant organic matter (OM) (2.0–5.0 wt%), appropriate thermal maturity (solid bitumen reflectance = 2.5–3.5%), and favorable kerogen types highlight the especially excellent hydrocarbon generation potential of the lower member of the Niutitang Formation and the Wufeng Formation. The development of pores hosted by OM particles and the presence of authigenic quartz account for the elevated porosity (3–5%) of these deposits and their adsorption capacity in the range of 1.5–2.5 m3/t. Strong top and base seals and a pressure coefficient (ratio of reservoir pressure to hydrostatic column pressure) greater than 1.4 of Wufeng Formation shale favor gas preservation in these deposits. However, poor associated sealing lithologies, an excessively high uplift amplitude (> 6900 m), and low pressure coefficient (< 1.0) account for diminished gas preservation in the lower member of Niutitang Formation. The low OM abundance and porosity of the upper member of Niutitang Formation and the Longmaxi Formation are more suggestive of a cap rock than a source or reservoir rock.

Significant contribution of haloalkaliphilic cyanobacteria to organic matter in an ancient alkaline lacustrine source rock: A case study from the Permian Fengcheng Formation, Junggar Basin, China

Alkaline lakes are productive aquatic environments, and related source rocks appear to possess considerable hydrocarbon generation potential. The Fengcheng Formation (Fm.) source rock is a good case to investigate organic matter enrichment and hydrocarbon generation characteristics of such alkaline lacustrine source rocks. However, the biological contributor to organic matter of the Fengcheng Fm. is generally controversial. Based on geochemical, biological, and theoretical evidence, a new understanding of the biological contributors to organic matter of alkaline lacustrine source rocks was reassessed. The depositional paloenvironment of the Fengcheng Fm. was reconstructed and compared to the Tumbiana Fm. (a typical alkaline lake case) by using alkaline minerals, trace elements, nitrogen isotopes, and biomarkers. The results of abundant alkaline minerals, Pr/Ph < 1, Sr/Ba > 1, B/Ga > 7, gammacerane index >0.2, and δ15N > 10‰ (published data) show that the Fengcheng Fm. was deposited in a reducing, hypersaline, alkaline lake, similar to that of the Tumbiana Fm. The biological contribution to organic matters of the Fengcheng Fm. was comprehensively investigated by biomarkers, fossils, and microbial community structure analysis. The low terrigenous/aquatic ratio, abundant 2-methylhopanes, and high αααC29cholestane-20R proportion of the Fengcheng Fm. provide geochemical evidence for a larger cyanobacteria input than land plants and algae. Identified stromatolites and Chroococcus fossils provide biological evidence for the active participation of cyanobacteria during deposition. The investigation of microbial community structures of modern alkaline lakes provides a theoretical evidence for the fact that cyanobacteria are the dominant phytoplankton in alkaline lakes. The dominance of cyanobacteria in alkaline lakes relates to the following aspects: the extreme resistance of cyanobacteria, their inorganic carbon-concentrating mechanism, their adequate sodium and carbon supply from alkaline lake water, and the inhibited growth of some species of algae within alkaline waters. In summary, haloalkaliphilic cyanobacteria are the primary contributors to organic matter of the Permian Fengcheng Fm. that was deposited in an ancient alkaline lake.

Geochemical characteristics and, origin of heavy oil in the periphery of Wenchang-B depression in Zhu III Sub-basin, Pearl River Mouth Basin, China

Heavy oil reservoirs have been discovered in the periphery of Wenchang-B depression in Zhu III sub-basin, but there is no relevant research on the geochemical characteristics and genesis of heavy oil. The characteristics of source rocks and crude oil were analyzed by various geochemical experiments. The results indicated that: (1) Second member of the Wenchang Formation (WC2) source rock has the largest hydrocarbon generation potential, WC1 and EP source rocks have similar characteristics, but EP source rocks have low maturity and Pr/nC17 greater than one; (2) Its heavy oil-density ranges from 0.91–0.97 g/cm3, with low sulfur content. The saturated hydrocarbon content in well Q4 is high, whereas it has low the non-hydrocarbon content. The carbon isotope values range from −28.2 ‰ and −25.4 ‰. Combined with the biomarker characteristics, the source of heave oil corresponds to WC2 and WC1 source rocks. Hence, there are two origins of heavy oil in the Wenchang-B depression, low-mature heavy crude oil (well Q4), and biodegradable heavy oil (well Q1). Clarifying the origin and source of heavy oil can provide more references for exploration and development.

A Nondestructive Alternative for Kerogen Type Determination in Potential Hydrocarbon Source Rocks Using Hyperspectral Data and Machine Learning

In Petroleum Geology, to assess the hydrocarbon generation potential in source rocks involves the determination of the kerogen type by some destructive method. The usage of such methods is a bottleneck in the process because it is time-consuming, requires specialized tools and personnel, and ends up destroying the rock sample, so it is not possible to do any posterior analysis. This study presents an alternative method for determination of the kerogen type that is fast and non-destructive using hyperspectral data and machine learning techniques. The method is validated using five distinct supervised learning algorithms that were applied to spectral data collected in rock samples from Taubat&#x00E9; Basin, Brazil, of an outcrop whose rocks have a wide range of hydrocarbon generation potential. Cores and samples were collected from the outcrop and had their kerogen type determined by geochemical analyses performed in the laboratory. The robustness of the method is evaluated in two distinct experiments. In the first one, the hyperspectral dataset was collected using a non-imaging spectroradiometer; in the second one, the method uses non-imaging hyperspectral data as training and is tested in hyperspectral images collected. In both experiments, the method was able to establish a relationship between selected spectral features and the kerogen type of the source rocks sampled. The results obtained in this paper are prospective for non-destructive classification of kerogen type (and, consequently, the hydrocarbon generation potential), since most of the models generated achieved accuracy above 0.8 in the validation step and 0.75 in the test step.

Origin and accumulation mechanisms of deep paleozoic oil and gas: A case study of the central Tarim basin, western China

Old strata and deep petroleum systems are becoming increasingly important. The Cambrian-Lower Ordovician petroleum reservoirs in the eastern Tazhong Uplift, central Tarim Basin, western China were studied comprehensively using various methods, including biomarkers, carbon isotopes of oil and gas, TOC and Rock-Eval pyrolysis of potential source rocks, as well as fluid inclusions, thin sections of dolomite rocks and Raman spectra of reservoir bitumen. The results show that the content of C 28 steranes among the C 27-29 steranes in most of the oil samples is greater than 0.25. The original hydrocarbon generation and expulsion potential of Cambrian and Lower Ordovician shale samples from the nearby Manjiaer Depression is considerable, and the oils are considered mainly derived from the Paleozoic shales in the Manjiaer Depression and the surrounding slops. Three notable types of oil and gas reservoirs were recognized in the Cambrian and Ordovician dolomite rocks: 1) the relatively well preserved primary reservoirs; 2) the residual reservoirs after deep oil-gas cracking with participation of thermochemical sulfate reduction (TSR); 3) the reformed reservoirs by the late charged high mature gas. In the vicinity of the No.1 fault zone, the effect of late gas charging and invasion is remarkable. They are mostly the mixture of gas cracked from both crude oil and heavy hydrocarbon gas in high mature stage. Oil and gas-liquid inclusions detected in the Cambrian reservoirs together with the Raman spectral characteristics of reservoir bitumen confirm the existed Cambrian paleo-oil reservoirs and oil cracking process. The gypsum-salt rock developed in Cambrian system is considered as a crucial factor for the primary oil and gas reservoirs, and the nearby areas within or below the strata where these gypsum-salt rock developed are suggested as favorable targets for deep to ultra-deep petroleum exploration. • Geochemistry characteristics of Cambrian and lower Ordovician oils were revealed. • Three modes of petroleum reservoirs in terms of formation mechanisms were proposed. • Major charging periods based on the fluid inclusions and burial-thermal history was suggested. • Hydrocarbon generation potential of Cambrian shale and Ordovician argillaceous dolomite was evaluated. • The sources and genesis of Cambrian and lower Ordovician oil and gas were clarified.

The effect of paleo-environment on hydrocarbon generation potential: Example from Vaca Muerta Formation, Neuquén Basin, Argentina

A 137-m continuous core from the Jurassic-Early Cretaceous marine derived oil shale with the maturity Ro about 0.7 %, representing the oil window in the Vaca Muerta Formation, Neuquén Basin, Argentina, was examined using geological, mineralogical, petrographic, and geochemistry techniques. Three distinct intervals were identified within the core: the upper carbonate-rich section with intense bioturbation, indicating dysoxic to oxic conditions that resulted in poor organic matter preservation; a middle section with decreasing carbonate content, suboxic bottom conditions, and higher organic matter content; and a lower section with higher detrital input and low carbonate content, suboxic to anoxic water conditions, and enhanced preservation of organic matter. Based on the presence of indicator fossils and geochemical parameters, a general trend of increasing organic matter content with lower paleo-oxygen levels was observed. The proportion of solid bitumen within organic matter increases with decreasing oxygen content, suggesting that organic matter deposited in anoxic conditions is more prone to transformation and hydrocarbon generation. There is a negative impact of increasing paleo-oxygen levels on the quantity and quality of organic matter, represented by its potential to generate hydrocarbons.

Source rock with high abundance of C28 regular sterane in typical brackish-saline lacustrine sediments: Biogenic source, depositional environment and hydrocarbon generation potential in Junggar Basin, China

In the brackish water sedimentary environment of the Junggar Basin in Xinjiang, the organic-rich shale and shale oil formation with relatively low maturity, is characterized by relatively high abundance of C28 regular steranes. However, the biogenic source of organic matter and favorable sedimentary environment for the type of source rock has been thoroughly classified. In this paper, organic geochemical and petrological, analyses of the Lucaogou Formation shale in the Jimusaer Sag, Junggar Basin in the north of Xinjiang Uygur Autonomy Region were carried out. The source rocks in the Lucaogou Formation are mainly composed of two types of maceral including lamalginite (cyanobacteria) and telalginite (green algae), with the former predominantly fueling the high C28 regular sterane content. Petrological, organic and inorganic geochemical analyses suggest that the lamalginite was developed in low-salinity water while the telalginite was developed in high-salinity water. Based on geochemical and organic petrological characteristics, both the lamalginite and telalginite have good hydrocarbon-generating potential, but in the lower thermal evolution stage of the Lucaogou Formation source rock, telalginite have higher hydrocarbon-generating rate.

Source rock pyrolysis and bulk kinetic modelling of Miocene sedimentary sequences in southeastern Sabah, Malaysia: The variability of thermal maturity to oil-gas producing kerogen

The study reports a new organic geochemical evaluation for a petroleum source rock in the Southeastern (SE) Sabah basin. The analyses focus on Kalabakan, Tanjong, and Kapilit Formation deposited in the deltaic-shallow marine environment stratigraphically from the Early to Late Miocene sequences. The basin sediments are part of the hydrocarbon prolific Tarakan basin, extending from the northernmost of Kalimantan Indonesia to the southeastern Sabah (mainly onshore area). The hydrocarbon generation of Kapilit and Tanjong Formation pinnacles the Total Organic Carbon (TOC) contents that range from 0.62 to 81.97 wt% and 0.97–92.96 wt% respectively. The dominant black shale in Kalabakan Formation has lower TOC content between 0.50 and 1.82 wt%. The results in the Rock-Eval S2 of Kapilit (0.31–351.61 mg HC/g rock) and Tanjong Formation (3.32–239.78 mg HC/g rock) have excellent source rock potential compared to the Kalabakan Formation (0.12–1.19 mg C/g rock) with fair to good source rock potential. All three formations give a wide maturity range of vitrinite reflectance (VRo) and Tmax values, from immature to over-mature stage. Stratigraphically from youngest to oldest Miocene sequences, the Tmax increases with increasing VRo values. The dispersion of organic matter that requires high maturity and overburden of thick upper succession over Kalabakan Formation reflects a higher maturity stage than the Tanjong and Kapilit Formations. Pyrolysis results in Kapilit, Tanjong, and Kalabakan Formation has HI values to varies between 50 and 498 mg HC/g, 157–367 mg HC/g and 14–110 mg HC/g TOC respectively. The binary plot of HI versus Tmax supported by Py-GC pyrolysis marks that the Kapilit source rock is dominated by Type II-III kerogen, potentially generating immature to mature oil and gas prone. Tanjong Formation portrays a mature to late mature stage of Type III kerogen with a minor Type II kerogen capable of producing mixing of oil and gas prone, with mainly gas. The Kalabakan Formation shows a post-mature Type III and IV kerogen that generates gas or barren source rock. In terms of bulk kinetic evaluation, both Kapilit and Tanjong Formation are derived from heterogeneous organic matter. The projected petroleum temperature varies substantially due to the compositional variation. The onset of bulk petroleum generation in the Kapilit and Tanjong Formation occur at 112 °C - 128 °C and 127 °C - 142 °C respectively. The results are consistent with the maturity generated where the Tanjong has higher thermal maturity than Kapilit Formation due to stable aromatic Type III kerogen. Generally, all samples show great variability in thermal maturity and hydrocarbon generation potential, which that be influenced by the tectonism and development of sediments in the basin. The Early Miocene source rock yields post mature gas prone and continues to generate hydrocarbon that consists of mature oil and gas prone from younger source rocks.

Palaeoenvironmental and tectonic controls on organic matter enrichment in the Middle Jurassic Dameigou Formation (Qaidam Basin, North China)

Lacustrine organic-rich shales are well developed in the Dameigou Formation within the Yuka Depression of the Qaidam Basin. These fine-grained sediments have been proven to have good hydrocarbon generation potential; therefore, understanding the sedimentary palaeoenvironment of these shales and organic matter enrichment mechanism is essential to increase prospects for shale oil and gas resources. The mineralogy, elemental geochemistry, and organic geochemical data combined with lithology of ZK23-1 well from the Yuka Depression, Qaidam Basin have been comprehensively analyzed to determine the hydrocarbon potential, palaeoenvironmental changes, and tectonic setting of the lacustrine organic-rich shales in the seventh member of Middle Jurassic Dameigou Formation (J 2 d 7 ). The profile of the ZK23-1 well is composed of three stages (Stages I to III) based on variations in bulk geochemical parameters and lithological observations. Mineral compositions of studied samples are dominated by clay minerals and quartz, with small amount of pyrite, calcite, dolomite, and plagioclase. Interestingly, all samples contain siderite, which is closely related to palaeoenvironment changes. Total organic carbon (TOC) content and hydrogen index (HI) vary significantly in the various lithologies, suggesting that oil shale holds the best hydrocarbon potential, followed by shales and mudstones. A warm-humid palaeoclimate prevailed in the Qaidam Basin during the Middle Jurassic; however, significant palaeoclimatic fluctuations occurred from Stages I to III in the J 2 d 7 , especially in Stage II. The climate varies from hot-arid to warm-humid in Stage II, likely resulting in changes in palaeowater column, chemical weathering intensity, as well as palaeoproductivity. The results of this study suggest that the Yuka Depression in the Middle Jurassic could be located at an active continental margin. Warm and humid conditions, as well as the tectonically quiescent setting with stable subsidence rate, are considered as two primary drivers for the enrichment and preservation of OM in the sediments of the J 2 d 7 . Ultimately, a comprehensive depositional model is proposed to interpret the evolution of deposition of the J 2 d 7 , providing new insights into the deposition of lacustrine organic-rich sediments linked to palaeoenvironment conditions and tectonic setting. • Three stages have been identified from ZK23-1 in the J 2 d 7 . • An obviously environmental fluctuation occurred from stage I to III of the J 2 d 7 . • Depositional models have been proposed to interpret the enrichment of OM. • The warm and humid condition and tectonically quiescent setting are popular. • Palaeoclimate and tectonic setting are primary drivers for OM enrichment.

Characteristics and exploration prospects of low-maturity oil reserves in the Bohai Bay Basin: A case study on the southern sag of the Liaoxi Depression

Source rocks and geological conditions favorable for forming low-maturity oil and gas are noted in the Bohai Sea. However, systematic research has not been performed on these oil and gas formations and resource potentials. Thus, to understand the low-maturity oil and gas formation mechanisms in the Bohai Sea and to assess their resource potentials and exploration prospects, the characteristics and low-maturity hydrocarbon generation potential of source rocks in the southern sag of the Liaoxi Depression were examined via experimental analyses, such as chromatography-mass spectrometry of saturated and aromatic hydrocarbons. Meanwhile, typical reserves were systematically analyzed in vertical and horizontal directions and compared to reservoirs in adjacent sags on the same planes. The formation mechanisms of low-maturity oil and gas were investigated in-depth, and the contributions of these oil and gas in the southern sag of the Liaoxi Depression were determined. The following conclusions were drawn: (1) The Shahejie Formation in the southern sag of the Liaoxi Depression was formed in saline environments so that the resulting source rocks can generate large amounts of liquid hydrocarbons rich in colloids and asphaltenes even at low maturity. These source rocks are characterized by their potential to yield low-maturity oils at early stages. (2) The deep LD4 and LD5 oil reserves in the steep slopes of the southern sag of the Liaoxi Depression are of low maturity. The low-maturity oils were produced from the saline source rocks in the Shahejie Formation. With the help of faults connecting the source rocks and the traps, oil and gas generated at low-maturity stages migrated into the traps along the steep slopes to form low-maturity oil and gas reserves. • Low-maturity oil and gas formation mechanisms in the Bohai Sea were explored. • Low-maturity hydrocarbon generation potential of source rocks in the southern sag of the Liaoxi Depression were examined.

Calculation and controlled factors of hydrocarbon expulsion efficiency using corrected pyrolysis parameters: A Songliao case study

In recent years, rock pyrolysis parameters combined with a mass balance method have been used to calculate the hydrocarbon expulsion efficiency. However, due to the experimental procedure of rock pyrolysis, the residual hydrocarbon amount (S1) is underestimated, and the hydrocarbon-generation potential of kerogen (S2) is overestimated, so that the hydrocarbon expulsion efficiency calculated from the pyrolysis parameters before correction is higher than the actual value. In this paper, the pyrolysis parameters were corrected by performing pyrolysis before and after the extraction of source rocks, and the hydrocarbon expulsion efficiency of the mudstone of the Qing 1 member of the Ha14 well in Songliao basin was calculated using the chemical kinetics method. The hydrocarbon expulsion efficiencies before and after the correction were considerably different, the hydrocarbon expulsion efficiency of the Ha14 well after correction was 17.5% lower than that before correction. The study show that the higher the abundance and maturity of source rock are, the higher the hydrocarbon expulsion efficiency is; the oil-type organic matter has a higher hydrocarbon-expulsion efficiency than the gas-type organic matter; the interbedded sand and mud type source-reservoir configuration relationship is beneficial to hydrocarbon expulsion; the underwater diversion channel phase has the highest hydrocarbon expulsion efficiency.